In subterranean reservoirs that produce gas, liquids (e.g., water) often are present as well. The liquids can come from condensation of hydrocarbon gas (condensate), from bound or free water naturally occurring in the formation (e.g., interstitial and connate water), or from liquids introduced into the formation (e.g., injected fluids). Regardless of the liquid's origin, it is typically desired to transport the liquid to the surface through the production wells via the produced gas. Initially in production, the reservoir typically has sufficient energy and natural forces to drive the gas and liquids into the production well and up to the surface. However, as the reservoir pressure and the differential pressure between the reservoir and the wellbore intake declines overtime due to production, there becomes insufficient natural energy to lift the fluids. The liquids therefore begin to accumulate in the bottom of the gas production wells, which is often referred to as liquid loading.
As the liquids begin to collect in the gas production wells, density separation by gravitational force naturally occurs separating the fluid into a gas column (substantially free of liquid) in the upper portion of the production well, a mixed liquid and gas column (with the percentage of liquid to gas increasing as the well depth increases) in the middle portion of the production well, and a liquid column (substantially free of gas) in the bottom portion of the production well. The liquid column can rise over time if the velocity of the produced gas decreases, thereby reducing the ability of the produced gas to transport the liquid to the surface. In this case, the liquid becomes too “heavy” for the gas to lift such that the liquid coalesces and drops back down the production casing or tubing. As the liquid column rises to a height in the production well where the hydrostatic pressure equals or exceeds the gas formation face pressure, the liquid detrimentally suppresses the rate at which the well fluid is produced from the formation and eventually obstructs gas production completely. Accordingly, this liquid needs to be artificially reduced or removed to ensure proper flow of natural gas (and liquids) to the surface.
There are several conventional methods for deliquification of a gas well such as by direct pumping (e.g., sucker rod pumps, electrical submersible pumps, progressive cavity pumps). Another common method is to run a reduced diameter (e.g., 0.25 to 1.5 inches) velocity or siphon string into the production well. The velocity or siphon string is used to reduce the production flow area, thereby increasing gas flow velocity through the string and attempting to carry some of the liquids to the surface as well. Another alternative method is the use of plunger lift systems, where small amounts of accumulated fluid is intermittently pushed to the surface by a plunger that is dropped down the production string and rises back to the top of the wellhead as the well shutoff valve is cyclically closed and opened, respectively. Another method is gas lift, in which gas is injected downhole to displace the well fluid in production tubing string such that the hydrostatic pressure is reduced and gas is able to resume flowing. Additional deliquification methods previously implemented include adding wellhead compression and injection of soap sticks or foamers.
Although there are several conventional methods for removing liquids from a well, few, if any, of the current commercially available methods provide sufficient means for removal of liquid from natural gas wells with low bottom-hole pressure. In addition, some of the above described methods may be cost prohibitive in times where the market value of gas is relatively low or for low production gas wells (i.e., marginal or stripper wells).